P-R-O-C-E-E-D-I-N-G-S
(1:30 p.m.)
CHAIRMAN BONACA: Good afternoon. This
is the meeting of the ACRS Subcommittee on Plant
License Renewal. I am Mario Bonaca, Chairman of the
Subcommittee.
The ACRS Members and consultants in
attendance are Peter Ford, Thomas Kress, Jack Sieber,
William Shack, and John Barton.
The purpose of this meeting is to review
the Staff Safety Evaluation Report related to the
application for license renewal of the operating
licenses for Units 3 and 4 of the Turkey Point Nuclear
Plant.
The Subcommittee reviewed the application
and the associated safety evaluation report with open
items on September 25, 2001.
The Subcommittee will gather information,
analyze relevant issues and facts, and formulate the
proposed positions and actions, as appropriate, for
deliberation by the full committee. Noel Dudley is the
Cognizant ACRS Staff engineer for this meeting.
The rules for participation in today's
meeting have been announced as part of the notice of
this meeting previously published in the Federal
Register on January 31st, 2002.
A transcript of this meeting is being kept
and will be made available a stated in the Federal
Register Notice. It is requested that speakers first
identify themselves and speak with sufficient clarity
and volume so that they can be readily heard.
Before I proceed with this, I would like
to point out that copies of this presentation for the
afternoon are in the back of the room, as well as
copies of the application of Turkey Point for a
renewal license.
We have received no requests for time to
make oral statements from members of the public
regarding today's meeting. However, we have received
written comments from Mr. Mark Oncavage, a member of
the public. I will now read his comments.
"I live 14 miles from Turkey Point and I
have safety concerns about the continued operation of
Turkey Point through the license renewal period. I
will not be able to attend the public meeting on March
13th, 2002 as I will be out of the country. I request
that you inform the members of the ACRS of my safety
concerns."
"One. In the early eighties the licensee
replaced steam generator lower assemblies in Units 3
and 4. The assemblies were too big to fit through the
existing doors, and so the doorways were widened.
Voids, up to four feet in length, were discovered in
the doorway."
"All indications I have seen show that no
further examinations for voids in the walls of the
containment buildings were ever performed. I am
concerned that thousands of voids in each building may
exist."
"These voids may accelerate age related
degradation by increasing internal surface area which
may be subject to oxidation, hydration, crumbling,
microbiotic action, and faulting. This degradation
could also weaken the tendons, reinforcement roads,
and the steel liner."
"As the plant ages, the structural
strength of the buildings may be increasingly
questionable in regard to an international terrorist
air crash. Region II officials have been aware of the
issue since June 2001 and have taken no action."
"Two. An unconfirmed story states that
Hurricane Andrew, 1992, isolated Turkey Point for
days. Diesel fuel for station power was only a few
hours away from being exhausted when help finally
arrived. Hurricane Andrew was a category four storm,
not a category five maximum hurricane."
"I'm concerned that the single road
servicing Turkey Point is easily blocked, a maximum
storm could disable diesel generators, diesel storage
tanks could be damaged, batteries could be
insufficient or damaged, the electrical grid could be
off-line, or the site could run out of fuel."
"A category five hurricane would bring a
higher storm surge, higher waves, and higher winds
than those experienced in Andrew. Station blackout
would be more likely."
"Three. The Turkey Point site, on the
shore of Biscayne Bay, has been raised to 18 feet
above sea level. A category five hurricane is likely
to produce an 18 to 20 foot storm surge with storm
waves superimposed on top of the surge."
"I'm concerned that hurricanes or
terrorist air crashes could collapse the auxiliary
building over the spent fuel pools. The concrete roof
collapsing into the spent fuel pool would radically
change the spent fuel geometry, possibly initiating
uncontrollable criticality."
"An intentional terrorist air crash could
possibly destroy the auxiliary building and
simultaneously damage the control room if the aircraft
made its approach from the east."
"Four. An issue the NRC staff and the
licensee refuse to acknowledge is the safety of spent
fuel after 2009. In that year both units 3 and 4 lose
their ability to off-load a full core. Public safety
has been put into a vacuum for the relicensing
process."
"All negative factors such as aging
management, hurricanes, station blackout, and
terrorist acts will be present, but no safety studies
of spent fuel storage options have been performed."
"As an informed citizen, I find the
relicensing seriously deficient. I urge the Advisory
Committee on Reactor Safeguards to refuse to meet on
this matter until all safety issues have been
satisfactorily resolved and an acceptable margin of
safety has been provided."
The staff will address these concerns as
part of today's presentation. We will now proceed
with the meeting, and I call upon Mr. Christopher
Grimes, Program Director for the License Renewal
Environmental Impacts, to begin.
MR. DUDLEY: Mr. Chairman, before we
begin, I would like to check to see if there is anyone
of the speaker phone, and if they could let us know
who is on the phone, and also let us know if you can
hear us.
CHAIRMAN BONACA: Is there anyone on the
speaker phone?
UNKNOWN VOICE: Yes, this is from
headquarters.
CHAIRMAN BONACA: Can you hear us?
UNKNOWN VOICE: Yes.
MR. DUDLEY: Okay. Fine. If there are
questions, we will need to direct them to you, and
then put the speaker phone closer to a mike so that
the transcriber can hear you.
UNKNOWN VOICE: Very good. Thanks.
CHAIRMAN BONACA: Good.
MR. GRIMES: Thank you, Dr. Bonaca. I am
Chris Grimes, and I am the Program Director for
License Renewal and Environmental Impacts. I think
first and foremost I would like to thank the advisory
committee on reactor safeguards, and particularly Dr.
Bonaca for your support, and assistance as we develop
the license renewal program.
As most of you have learned through the
trade press by now, on April 7th, I will assume new
responsibilities, and I think a large measure of the
accomplishments of the license renewal program and the
focus on effective aging management, and maintaining
plant safety through a relicense period, was due in
part to the excellent working relationship that the
staff established with the advisory committee.
As you said, Dr. Bonaca, the purpose of
this meeting today is for the staff to describe the
resolution of the open items in a safety evaluation
report, and we are going to do that. I am going to
introduce Raj Auluck, who is the senior project
manager in charge of the Turkey Point license renewal
review.
And he is going to lead you through the
resolution of those open items and address the issues
raised by Mr. Oncavage.
MR. AULUCK: Good afternoon. I am Raj
Auluck, and I am the project manager for the review of
the Turkey Point License Renewal Application. The
purpose of today's meeting is to present the staff's
review of the Turkey Point License Renewal
Application, and to describe the resolution of the
open items, and the basis upon which we will move
forward to make a recommendation.
I would like to introduce two staff
members, Jim Medoff who is on a rotational assignment
from the Division of Engineering, and who will be
assisting me in the presentation; and I also have
Caudle Julian from Region II, who has been the lead
inspector and team leader for all of the inspections
performed by Region II for license renewal
applications.
We also have a telephone bridge set up
with the headquarters, and staff members are available
to support this meeting.
Before we do that, I would like to make a
comment on the letter to ACRS. If you read the
letter, we can try to group these concerns into four
bullets as shown on the slide. They are effects of
voids on aging degradation rates and the structural
integrity of concrete containment structures.
The second one is the effect of design
basis hurricane wind speeds and storm waves on safe
operation of Turkey Point Nuclear Plant.
The third one is the effect of terrorist
air attacks on the safety and operability of the
Turkey Point nuclear units. And the four one is the
Turkey Point spent fuel capacity.
These are all old issues, and have been
raised by Mr. Oncavage in some form or another
previously, and they have been addressed by the staff.
We will go into some more details later on in our
presentation, but at this time I would like to go back
to the review of the application.
CHAIRMAN BONACA: So do you plan to
address these?
MR. AULUCK: Yes, we plan to come back to
these.
CHAIRMAN BONACA: After you address the
open items and the application?
MR. AULUCK: Yes. The application was
received a little over 18 months back, and this was
the fifth application received by the NRC. Four
applications have been approved so far, and this is
the First Westinghouse PWR, and this is two unit site,
and each unit is designed for 2300 megawatts thermal.
The site is shared by two oil and gas
fired generator units. The plant is located about 25
miles from Miami. For the Unit 3, the license expires
on July 19th, 2012; and for Unit 4, on April 10th,
2013. This application is for a 20 year extension of
the license.
This slide is an update of what I
presented in September of 2000. Items to note are
that the SER was issued on August 17th, 2001, and
final SER resolution of items, with open items, was
issued on February 28th.
Final environmental impact statement
related to the staff's complete optional final
inspection was issued on January 15th of this year.
The next milestones are to complete the staff's
presentations briefing the ACRS subcommittee and the
full committee next month, and prepare a Commission
paper with recommendations.
Originally, the schedule, which was issued
in October of 2000, was based on a 30 month schedule,
and since there was no hearing, and a few open items,
we were able to move up that schedule to this current
schedule.
Now, let's just talk about the staff's
review and the process Now, two sets of regulation
requirements govern the review of license renewal
applications.
First, pursuant to 10 CFR Part 54, the NRC
staff conducts a technical review of the license
renewal application to assure that the public safety
requirements have been satisfied.
The second, pursuant to 10 CFR Part 51,
the NRC staff completes an environmental review of the
license renewal, focusing upon potential impacts of at
least 20 years of operation.
And as there many programs which routinely
monitor and assess plant operations that our license
renewal review focuses upon those potential damaging
effects of aging that are not routinely addressed by
the oversight programs.
Part 54 requires renewal applicants to
demonstrate how their programs will be affected in
managing the effects of aging during the proposed
period of extended operation.
This is a detailed assessment conducted by
the competent structural level arrived at the systems
level. The staff review consisted of a review of the
applicant's scoping and screening methodology, and a
review of the aging management programs, and a review
of the time limited aging analysis identified by the
applicant meeting the criteria of 10 CFR 54.3.
These reviews are supplemented by site
audits and inspections by the NRC staff. We will have
a separate slide to summarize the results of the
inspections.
The scoping and screening methodology
review was done in two parts; desk top review, which
is basically an initial review of the application, and
the supporting information.
The second is the on-site audit, where the
staff, about 5 to 7 staff members, with support from
Region II, went to the site and reviewed the LRA
implementation process, and reviewed engineering
reports, and engineering procedures, design
documentation, and had an opportunity to discuss
individually with the systems engineer or with people
responsible in those areas.
This site audit is completed early in the
review process, and in the case of Turkey Point, it
was completed in November of 2000, which is a little
over two months after the application was received.
The major audit findings indicated that
the applicant's approach is consistent with 10 CDR
50.4, and the scoping process was very defined, and
proceduralized; and, third, the audit provided
confirmation of the process implementation.
I would like to mention that it was during
this audit early in the review process that the issue
of interaction of non-safe piping versus safety piping
was first raised, and then just became an open item.
As you can see, 10 CFR 54.29 describes the
standards which must be met before the Commission
issues a new license. We have already talked about
the first two items. The first one is the issue of
safety, and the second one relates to a normal review.
The third one I would like to make some
comments on that. There was no hearing on this
application, but there were two requests, five
petitions to interview, and a request for a hearing.
On January 18th, 2001, the Atomic Board
and Licensing Panel held a prehearing conference in
Homestead, Florida, to hear the petitioner's standing
and admissibility on the contingents.
In their order issued on February 26th,
2001, the board ruled that although both parties have
standing to intervene, but neither petitioner
proffered admissible contingents.
Their intervention petitions therefore
must be denied. Most of the issues raised in Mr.
Oncavage's letter to the ACRS was in some form or
other filed with these contingents, and thus have been
found to be inadmissible.
The Board also ruled that these
contingents raised issues that fall beyond the scope
of license renewal reviews, and in new proceedings on
March 19th, 2001, Mr. Oncavage, one of the
petitioners, appealed the Board's decision to the
Commission. On July 19th, the Commission issued an
order affirming both decisions.
CHAIRMAN BONACA: I have a question.
During our subcommittee meeting of September 2001, we
had presentations regarding scoping and screening, and
the process broken down into five components that fall
into the rule.
And the impression that we got was that
the application, the reviews of the application were
pretty scrutable and clear. There were over 200
requests for additional information that you raised I
believe on this application.
Is there any conflict between the two? I
mean, why did you have so many requests for additional
information? Was it mostly because you were just --
MR. AULUCK: As I go later on, there were
about 215 requests for additional information on this
application, which was substantially lower than the
one before it, which was in the high three hundreds.
CHAIRMAN BONACA: Okay.
MR. AULUCK: And I assumed that the next
applications, you know, that they should be much less.
And because most of the time the applicants learned
from each other, they go and review the previous
applications, and they review the RAIs issued by the
staff.
So they are familiar with what the staff
is looking for than specific areas. So that is my
expectation.
CHAIRMAN BONACA: And so this application
in your judgment confirms a trend which you were
pointing out that lessons learned are being utilized,
and I think the impression that I had was that this
plant has utilized lessons learned.
MR. AULUCK: If my memory is correct, I
think one of the earliest applications had RAIs in the
range of 400, and then 300, and then 200. So the
trend is definitely going down.
CHAIRMAN BONACA: Also, you had a
substantial amount of inspection time on this
application. I believe probably more than what others
have seen before, and that probably was also due --
MR. AULUCK: Yes. We had some additional
interaction with the applicant prior to sending RAIs.
One was in a meeting to clarify the application, and
go walk through what they had in mind when they
prepared the application and to help us navigate the
issues and problems in different sections.
CHAIRMAN BONACA: You will talk about
inspections later, right?
MR. AULUCK: Yes, we have a separate slide
on the inspections.
CHAIRMAN BONACA: Thank you.
MR. AULUCK: So of the slides repeat some
of the September presentation. The applicant
participated in several industry groups or license
renewals, including the Westinghouse Owners Group
effort that developed a series of generic technical
reports intended to demonstrate that aging effects on
the reactor coolant components would be adequately
managed through the period of extended operation.
The four Westinghouse reports specifically
were submitted for the staff's review. Usually the
staff's safety evaluation of the topical reports is
intended to be stand alone documents, and in this
application these reports were not incorporated by
reference because the staff review was not completed
by the time that the application was submitted.
But the applicant addressed the
applicability of these reports to their application,
and conformed whenever an SER was issued, or there are
any other changes.
In addition, the applicant prepared many
internal license renewal documents under the QA
program for use in the preparation of the application,
and training of their staff members.
If I remember last time, there was a
question raised on the training of their internal
staff members, and how the knowledge would be imparted
to other staff members on an on-site audit, and
conformed that to -- well, there is a substantial
amount of documentation on the scoping and screening,
and design basis documents, that is available.
And they used that in the training for the
training of classes.
CHAIRMAN BONACA: This WCAPS being
reviewed as an SER?
MR. AULUCK: All of these documents are
final now, and the SER has been issued, and I think
the dates are on the slide.
The staff reviewed selected portions of
the (inaudible) documents and scoping documents, and
AMR inspection documents, and based on our discussions
with the applicant, apparently as I mentioned earlier,
prior to preparing their application they had visits
to other applicants.
They had a peer review, and so they took
some advantage of some experience in the industry. We
have already talked about the number of open items,
but at the end of our review, during the draft, and
when we issued a draft SER, there were four open
items.
And we had gone over those items during
our meeting of September of last year. Here is a list
of those four open items. The first one is scoping
for Seismic II over I, and the reality interaction of
non-safety piping and competence with the safety
related systems and components.
The second one was the acceptance criteria
for Field Erected Tanks Internal Inspection, Aging
Management Program; and the third is the scope of the
reactor vessel head alloy 600 penetration inspection
program.
And the last one was the reactor pressure
vessel underclad cracking. The first one as I
mentioned, it was noted when we did the scoping
inspection, and at that time the staff did not agree
with the applicant's scoping criteria for Seismic II
over I piping.
The staff's position has always been that
Seismic II over I piping systems, whose failures could
prevent safety related systems and structures for
completing their intended function should be included
within the scope of license renewal.
This was the same issue which was under
discussion with another applicant at that time, and so
we requested that the applicant, Turkey Point Power
Plant, to wait until the issue is resolved on the
other application.
And that was the October time frame, and
so once that was resolved and the staff's position was
agreed upon, Florida Power and Light responded on
their number one on our RAI on this issue.
The major concerns that the staff had was
that because of age degradation non-safety related
piping could fail anywhere along the land, and not at
postulated break locations.
So with that in mind, Florida Power and
Light reviewed the areas, and they had used the area
based approach in identifying II over I issues, and
there were nine areas, and based on the supplemental
review, they found that they had to make changes, and
add other extra piping into the scope in five of those
areas.
And this was in the auxiliary building,
the control building, the turbine building, and yard
structures. And to manage the aging effect, the
applicant using the chemistry controlled program, flow
executed corrosion, and systems and structures
management program as applicable, to manage the of
effects of aging.
The staff finds this response acceptable
and therefore this open item is closed. Any
questions?
CHAIRMAN BONACA: Well, for the record, it
is not that some elements, such as no safety related
piping had not been included already. The issue was
that the piping, or the issues at hand were really the
corrosion or erosion of piping, and not other issues,
as for example, a hemorrhage line or break locations
that would cause additional piping to possibly fail in
that system interaction.
That was really --
MR. AULUCK: Yes, sir.
CHAIRMAN BONACA: So that is the
clarification that really made the additional scope.
MR. AULUCK: Yes. The next one is
acceptance --
CHAIRMAN BONACA: We, by the way, had a
presentation of the subject this morning from the site
during our walk down and I don't know if there are any
further questions from the members regarding these
issues of 2 over I?
DR. BARTON: I think the questions that I
had on II over I have been resolved based on a
discussion that we had at the plant site this morning.
MR. DUDLEY: Mr. Barton, you may want to
for the public explain what you heard at the site that
allowed you to reach that conclusion.
DR. BARTON: Well, Seismic II over I, I
think, has been an issue with every application that
I have been involved in reviewing, and so I guess it
has been generic with every application.
And what I heard today which was a little
different, and which helped clarify for me, was that
maybe it is not just Seismic II over I, but it is
really what failures of non-safety related systems or
components, based on the failure of that system or
component, could impact a safety related system.
And that to me is broader than just
seismic II over I, and I think this applicant has
understood that and addressed it, and I think that
some of the other applicants have not really got the
word yet, or got the picture on this thing.
And what I would suggest the staff do is
to kind of clarify this issue, because unless they do,
I think it is going to continue to be an issue, an
open issue in every application that comes down the
pipe.
MEMBER KRESS: And the question that I
have about that, John, is that when you look at the
impacts of the non-safety and safety, you have to do
something, and I have not seen criteria for what they
do to determine that impact.
And that needs to be clarified to me, and
I don't know how the staff reviewed that part of it.
MEMBER SHACK: The area of method where
they looked at what was impacted?
MEMBER KRESS: Yes.
CHAIRMAN BONACA: I think that is a
program that would have to be established to deal with
those things.
MEMBER SHACK: But I think one of the
clarifications at least is that the staff is not
asking anybody to postulate failures in the system.
They are really looking for systems where failure
mechanisms have been observed, or applaudable, or
expected in fact.
CHAIRMAN BONACA: Right.
MEMBER SHACK: And to then deal with that
experience, and so it is not a postulated failure. It
really is an experience-based argument for selecting
the systems that need to be addressed, which I think
is a risk-informed, performance-based kind of approach
to it.
CHAIRMAN BONACA: And for the record by
the way, we have seen significant guidance from the
NRC on a previous application, and I think the latest
one we saw was Hatch. And for that, we recommended in
fact the guidance that we provided to all the
licensees, because the guidance was very clear.
I mean, the first time it was a document
where the logic used by the staff was very, very,
clearly stated, and the concern was that until now any
time you had an evaluation of impact, it had to be
Seismic II over I, or was original line break, for
example, which suggests specific locations where
stresses may be.
This has to do with the aging of the
piping, and so therefore maybe corrosion or erosion
effects, which may cause failure of segments in
different locations, and those are realized under
original line break or Seismic II over I.
So that's it is introduced at other
locations now. Now, insofar as the specifics, I
believe the point that Dr. Shack is making that the
license has included those segments in their
inspection program, and monitoring programs, so that
they can essentially track those segments, and prevent
those kinds of failures from occurring.
And should they occur, of course there is
going to be an impact on certain electrical components
that Dr. Kress is bringing up here, and I am sure that
they will be -- well, they must have been evaluated
for the potential for the -- or otherwise you would
not have put that piece of piping into the problem.
MR. AULUCK: I think that the staff has
prepared a position paper and it has been shared with
NAI, and it may not be final yet, but I think there
has been substantial progress made on it.
CHAIRMAN BONACA: I think that is a
question, and hopefully it will be the last time that
it comes up.
DR. SIEBER: I guess I would like to ask
a question just to clarify something in my own mind.
Seismic II over I has to do with having a non-safety
system in a seismic situation above a safety system
where its failure of collapse would disable the safety
system.
And it also includes pipe width, and jet
impingement. The one thing that I did not see is if
you have a Seismic Class II failure that doesn't have
jet impingement, and does not have pipe whipping, but
does flood the room where it is at, was that included
in your classification, the internal approach?
MR. AULUCK: Yes, flooding is included.
MR. GRIMES: This is Chris Grimes. I
would like to clarify that the reason that we used the
term, Seismic II over I, is that it stimulated this
issue about non-safety system failures that could
affect safety related equipment.
Actually, the memory tool that I use is
safety interaction with non-safety are SINS. The SINS
of the design are that there were postulated pipe
breaks that were based on stress.
The design of this Seismic Category II
piping presumed that so long as you held it up that it
would not fall down in an earthquake.
CHAIRMAN BONACA: Right.
MR. GRIMES: But the criteria for license
renewal says that evaluate failures of non-safety
systems, irrespective of the design basis. And the
staff evaluation and the guidance that we are
developing based on this experience, hopefully is
going to clarify what we consider to be credible age
related piping failures like Seismic Category II
piping that simply cracks, or breaks, or leaks, or
whatever.
And as FP&L said, it was not our intent to
change the design basis so much as it was to have them
reflect on what credible failures there are in these
systems, and that you need to provide for credit for
the aging management programs.
During your tour this morning, you
understood that Florida Power and Light has
substantial aging management programs that they
conduct as a prudent measure to maintain the plant to
protect their investment.
At the heart of the issue here is which
ones of those need to be credited on a licensing basis
so that they now come under a regulatory control for
future changes to those programs and commitments.
CHAIRMAN BONACA: Thank you.
MR. AULUCK: The next open is the
acceptance criteria for Field Erected Tanks Internal
Inspection. This is a new program, and at the time
that the draft SER was issued, the applicant had not
developed the program fully. That's why it became an
open item.
So once the program was completely
developed, the staff reviewed it and found it
acceptable. And here the main issues were acceptance
criteria for a one-time inspection of the tanks.
The acceptance criteria should also state
the task at which additional inspections will be
implemented. And the applicant to describe any
provisions, if any, for additional volumetric or
surface examinations on one-time inspections to read
extensive loss of material.
And lastly the applicant justified a one-
time inspection program rather than a periodic
inspection for each of the tanks.
In response the applicant stated that the
acceptance criteria will be the design conclusion
allowance, any loss of material greater than the tank
corrosion allows will require corrective action to
ensure that the tanks intended functions are
maintained under all design commissions.
The time at which additional inspections
will be implemented will be the corrosion of the steel
tank. With respect to the one-time inspection program
rather than the periodic inspection for each of the
tanks, the applicant stated that currently none of the
tanks is inspected periodically.
These tanks are fabricated from carbon
steel, and services are required to reduce corrosion.
Each of these tanks contain treated water with an
allotment of air and gas.
A one-time inspection will utilize a
direct or diverse, or remote t.v. cameras, or other
instruments, to observe the inside surfaces. In
addition, the applicant plans to use the chemistry
control program to monitor the condition of the
treated water in each of these tanks.
The application also stated that although
these tanks are not currently inspected on a periodic
basis, the water tank was recently inspected as part
of the pre-inspection and performed prior to the
installation of a floating tower inside the tank.
And they did not see any defects or any
degradation of the coatings, and the applicant's
position is that other tanks will be just like that
and show little or no degradation.
Therefore, one-time field tanks internal
inspection will provide the confirmation that no aging
effects require management for these tanks. If in
this one-time inspection, if they do find something,
they will put it in their corrective action program,
and take appropriate action.
CHAIRMAN BONACA: For this one did they
enter the renewal period?
MR. AULUCK: Yes.
CHAIRMAN BONACA: And they will be
affecting all the tanks?
MR. AULUCK: All the three tanks.
MEMBER FORD: Could I just ask another
question on this? Do I understand that the internals
of the tank have been inspected once and no
degradation has been seen?
MR. AULUCK: Only two of the three tanks.
MEMBER FORD: Only two of the three tanks
have been inspected once, and no degradation?
MR. AULUCK: No, one was on the storage
tank that they did find degradation, and they were
recoated and that was because of inferior coating done
earlier.
MEMBER FORD: Okay. Is there any other
industry, and not particularly the nuclear industry,
but any other industry experience to indicate that the
particular coating systems that you are using and in
the environment that you are using them in, that it is
justifiable to go forever without inspecting. Well,
forever is a long time.
MR. AULUCK: I am sure in every industry
that they will do some inspection, an exterior
inspection, and that will indicate or provide some
indication that they will have to have some
inspections. It may not be interior; external surface
inspections.
MEMBER FORD: This makes me feel a bit
uncomfortable in the area of corrosion, because you
are going to take it as a given, and that you will
inspect it once in time, or maybe twice in time, and
make the assumption that for another 20 years nothing
is going to happen.
MR. AULUCK: But the very purpose of one-
time inspection is that you are not expecting any
corrosion.
MEMBER FORD: Well, that is precisely my
point. This is a reactive technology, and generally
we don't know about it until we forgot it, and that is
why I asked if there is any experience in other
industries to back up that presumption.
MR. AULUCK: I do not know, but I do not
think that the experience is not on a given site. I
am sure if any on any site a degradation is found that
information will be passed to the other members and a
generic action will be proposed, or some action will
be taken. It is a sharing of information.
MR. GRIMES: I will respond first, and
then I will also ask Dr. Shack to see whether or not
there is a squeak from under your chair, and if there
is anybody on the phone that wants to contribute to
this.
But my observation is that we no longer
have the benefit of Dr. Davis' corrosion experience,
but the standards that were established for the
coating program were intended to provide a system that
would inhibit corrosion in tanks or other receptacles
like tanks, so that they did not need to be inspected,
and so that they would be protected against the
corrosion.
And it is not so much that we have
confidence that we can simply let them sit there and
never expect to have any experience, or any reason to
inspect them.
What we concluded is that there is no need
for a special periodic routine specified inspection
activity with acceptance criteria, and that that kind
of level of inspection is necessary.
A one time inspection will verify our
presumption that the coating program either works as
intended, or it will direct us to a specific kind of
maintenance activity.
We have done that in a variety of areas,
and we have explained how we are confident that the
reliance on one-time inspections to verify certain
assumptions about the lack of evidence of an aging
effect that would effect the safety function can be
confirmed by a one-time inspection.
And then also rely on the feedback systems
from operating experience, including insights that are
brought into our industry from other industries, like
the NACE programs, the Petroleum Institutes.
Those contributed to this insight and
this conclusion. So we are confident that that the
one time inspection, as supplemented by that ongoing
experience feedback to identify whether or not
something needs to be done beyond this conclusion and
this one-time inspection, that safety can rely on that
basis.
CHAIRMAN BONACA: Steve.
MR. HALE: Yes, I just wanted to clarify
-- oh, I'm sorry, Steve Hale, Florida Power and Light.
There are five tanks that are within the scope of this
program. There are two RWTs, and the two condensate
storage tanks, and a demineralized water storage tank.
We have been in three of them, and we plan
as part of our commitment to go in those three before
our license expires, as well as the two RWTs. So we
are not going down the path of not doing inspection at
all, but we will be in all the tanks before our
license expires, and we have been in 3 of the 5
already.
CHAIRMAN BONACA: The question that I have
is that you did experience degradation in the
condensate storage tank, or one of the condensate
storage tanks, and you had good reasons to explain why
you had that, and you corrected that reason.
What is the operating experience for other
power plants in the country regarding this performance
of CSTs? Do they have similar experience to what you
have had, or they normally don't see degradation?
MR. HALE: Typically, they have not seen
degradation, and it is really a function of what you
have exposed the tank to. Certainly that based on our
review -- and we have not seen anything, because as
part of our aging management reviews, we looked at
industry experience.
We also drew on EPRI and some of the work
that was done by the B&W owners group that all of the
owners groups have bought into and utilized, in terms
of aging effects and that sort of thing.
CHAIRMAN BONACA: But after you removed
the causes of the degradation in the CST, you did not
really go back and verify that in fact degradation is
happening anymore did you?
MR. HALE: No, we haven't gone back into
the CSTs, but again we --
CHAIRMAN BONACA: And with a one-time
inspection, that will give the conformation.
MR. HALE: But we plan to go into it again
before our license expires, and we are also looking
externally. We are looking regularly externally.
So the failure that we had with the CST,
or not failure, but the corrosion we saw in the CSTs
was evident from the external surface as well.
And we think that would be a leading
indicator if indeed you were having problems.
CHAIRMAN BONACA: Now, for one previous
application, we accepted a one-time inspection also on
the basis that if felt that you would have degradation
resulting in leakage that was visible, and actions
could be taken really to maintain the plant safe as
you repaired that.
So that was one of the reasons, but
certainly it is a consideration, but what I am saying
that as far as this CST, if you go back into the CST
and you find that it has again degraded, in spite of
all of your corrective actions, you would have to
establish a programmatic initiative to inspect it on
a certain specificity, right?
MR. HALE: Yes, certainly, and that is
what we clarified in the closure of the open item;
that if indeed we found extensive material loss that
we would utilize additional inspection methods, as
well as establishing a periodic inspection as a result
of those findings.
DR. SIEBER: Let me attack this just a
little bit more. When you get corrosion in tanks like
that, it is typically pitting corrosion, which results
in leakage.
And so I wonder from a safety standpoint
what the impact of that is, for example, in a
condensate storage tank, refueling water storage tank,
demineralized water storage tank.
You are going to see the leakage, and the
reactor is not in danger at that point, and you may
some day have to shut down so that you can repair
degradation to a tank, but it is to my mind the
consequence of having leakage from any one of these
tanks other than the diesel tanks is something that
can be dealt with in due course.
And the diesel tanks to me are more of an
environmental issue, and the detection of leakage
there is much simpler since they are usually in a
vault, where you can measure how much leaked out and
capture it. Is that correct or incorrect from the
staff's viewpoint?
MR. SMILAN: My name is --
CHAIRMAN BONACA: If you would introduce
yourself, and speak in the microphone. Thank you.
MR. SMILAN: Thank you. My name is Stan
Smilan, and I was a Captain for United Airlines, and
I flew for United Airlines for 36 years. We had
corrosion problems with airplanes --
DR. SIEBER: You sure did.
MR. SMILAN: And if you will recall, we
had an airline decompress, where they lost part of the
fuselage, and had a stewardess who was sucked out of
the airplane.
On United Airlines, we had a failure of a
cargo door on a 747, and which resulted in the
airplane having to abort, and make a return to
Honolulu on two engines.
To my mind, it seems to me that we are
talking here about pressurized reactors. Now, are
these pipes within a pressurized environment, and how
an you compare a pressurized environment to a diesel
tank that is not pressurized, and that wouldn't start
to leak. That is my question.
DR. SIEBER: All the tanks that we are
talking about are static end tanks, and they are not
pressurized, except for the hydrostatic head within
them.
So we are not talking a situation like an
aircraft fuselage that can decompress, and whose
consequences are sometimes serious. These are less
so.
MR. SMILAN: This is not general
knowledge, but at one time United Airlines was
considering refurbishing 747 aircraft at their Oakland
facility. They built an entire facility to do this to
re-skin the airplanes.
And after these decompressions took place,
they realized that because of the corrosion this was
a pretty bad idea, and they would not go forward with
it.
Singapore Airlines, by contrast, never
keeps an airplane more than seven years. And they
sell the airplanes and they have the youngest fleet
worldwide.
And one of the reasons is that they are
very much concerned about corrosion, and this
particular plant was built for $285 million. By
contrast, the Schorm facility out on Long Island, cost
$6.5 billion dollars, and some estimates said it went
to $7.2 billion. That plant never opened.
There was a different issue involved and
it had to do with the evacuation of the plant. But
just by virtue of the fact that this plant was built
for $285 million, these two units, each $285 million
each, they were very controversial at the time.
The literature I read on the subject
indicates that there was a split amongst the
scientific community and within the Atomic Energy
Commission, almost half of the scientists quit, and
formed the Union of Concerned Scientists because they
were so concerned about the design.
And you have to contrast the fact that
this plant was built for $285 million; whereas, to
build a new plant today would run into the billions of
dollars.
And I am so concerned that there are no
intervenors here to offer responsible rebuttal. And
let me just make one more point, and this will
constitute what my input would be as a public
commentor.
We had a concept that was introduced on
the airlines that was called cockpit resource
management procedures. The airlines were very
concerned that the captain would make a decision and
institute some sort of a procedure that could result
in a loss of the airplane if he acted on his own.
Now you people on this advisory committee
I think are very much in the same context as a captain
on an airplane. You have got to make these decisions.
The captain is now charged with the
responsibility of soliciting input from the rest of
his crew. He has got to consult with the co-pilot,
and the flight engineer, and reach out beyond the
cockpit for additional resources, and even consult
with the manufacturer.
He can have the manufacturer in Boeing, or
McDonald Douglas on the radio to consult with them.
And the people who designed the system, and have them
consult with him.
And the captain can't get off the hook by
saying that nobody came forward to advocate. He has
to solicit. You have communities here, and you have
counties, and you have municipalities, and you have
the State, that has not stepped forward to provide an
intervenor at these proceedings.
And they should be providing the funding
for technical consultants. One very last final item.
At Schorm, I participated in the county hearings and
their environmental committee. The county was the
only effective intervenor in the Schorm proceedings,
and that was Suffolk County, in New York.
They hired independent counsel, provided
that independent counsel with $50,000 to get technical
consultants. The Long Island Lighting Company -- and
I was furnished a letter that was circulated among the
legislators, and I wrote an article for the New York
Times.
And the Long Island Lighting Company had
the -- they lobbied to have the county legislature
reduce the funding from $50,000 down to $18,000. They
only could hire people who had no expertise whatsoever
regarding the safety of the containment vessel. And
that was a G.E. boiling water reactor.
Now, at the licensing hearings, I stepped
forward, and one of the things that I said was that it
was if as the door had been locked, and the Long
Island Lighting Company had tried to prohibit anyone
from coming forward and offering responsible rebuttal
to the presentations being made by the utility.
And I think the same thing is happening
here, and one of the things that we really have to
keep in mind is that in 30 years according to
statistics being furnished by the South Florida Water
Management District, the population of South Florida
will grow to 15 million people.
The State now has 15 million people, and
the population in 30 years will double, and 15 million
people will be located south of Fort Pierce.
You have to consider what licensing extension you are
going to get in the context of the increased
population down here.
And the fact that the Price Anderson Act
right now will only reimburse losses of up to 6 or 10
billion dollars, and the estimates that I have read in
the paper was that losses down here from a
catastrophic accident with this reactor could amount
to 20 to 60 billion dollars.
And I think that we are on very dangerous
ground, and I would recommend that you people go
slowly, solicit from the municipalities their input,
and ask them to provide them with another opportunity
to step forward as intervenors and to provide funding
for technical consultants to come before you to
provide responsible rebuttal.
These people are all well-meaning here,
but it is an adversarial procedure, and there are no
adversaries coming forward. Thank you. Incidentally,
I am running for the State Senate.
MR. GRIMES: Getting back to your
question, Mr. Sieber, these are low pressure systems.
They are tanks, and essentially holding tanks. We are
going to get into a couple of issues after this where
we are going to talk about primary cooling, pressure
boundary, and how different that circumstance is.
But I believe your characterization that
because these are essentially pools and that are water
sources that are drawn on by the reactor systems,
that's why we feel that the coating systems, along
with the experience thus far, that we have not seen
catastrophic failures, that we would expect to see
leaks before we would see failures in the tanks.
So there is a high degree of confidence
that these water sources are going to be available
when they are needed, and any action to deal with
corrosion on these tanks.
And we now have in addition to several
hundred years worth of reactor experience, we have
drawn on the experience from these other industries to
tell us that these kinds of tanks don't require the
same level of an inspection and maintenance that other
systems do.
DR. SIEBER: Thank you.
MR. AULUCK: Moving to the third item.
Jim Medoff will talk about these next three items.
CHAIRMAN BONACA: Before we proceed, I
would like to make a comment regarding previous
comments by citizens here. That is exactly why we
came on site. We have no requirement to come locally,
and to have this open meeting.
So personally I appreciate your comments;
and second, this is just a subcommittee meeting, and
we are going to meet on this matter in April in
Washington, and you are absolutely welcome to be
there, and to present your points of view. With that,
I thank you again for your observations.
MR. MEDOFF: Good afternoon. My name is
Jim Medoff, and I am a materials engineer with the
materials and chemical engineering branch of NRR. I
am currently on a rotation to the license renewal and
environmental impact program of NRR.
I am here to address two open items, the
first one being on the Alloy 600 inspection program,
and the second open item that I will deal with will
deal with the issue of unclad cracking of the reactor
vessel.
And lastly I would like to briefly talk
about Mr. Oncavage's concerns as addressed in his
recent letter to us. Regarding the open item on the
Alloy 600 program, the USNRC has been investigating
the issue of primary water stress corrosion cracking
of Alloy 600 penetration nozzles since 1990, when one
of the French plants experienced cracking in one of
their vessel head nozzles.
Following the cracking of that in France,
the agency had initial dialogues with the industry
owners groups to find out what whether their plants
were inspecting the vessel heads of U.S. pressurized
water reactors.
Industry came back to us in 1991 and 1992
with a series of safety evaluations and basically
concluded that it was not an issue for their plants at
the time, and that it was more of an economic issue.
We took a look at their assessments and
wrote a safety evaluation in 1993, and basically
concluded that based on the amount of time that the
plants were operating that the issue of stress
corrosion cracking in these nozzles was not an
immediate safety issue, but we differed from the
industry and concluded that it might be an issue in
the long term since the phenomena was really dependent
on time and temperature.
We had a number of dialogues with the
industry and basically the industry agreed to perform
a number of volumetric inspections at a number of
plants, where they had projected to have the most
susceptible nozzles in the industry.
And during one of these exams, they found
a number of cracks at D.C. Cook, at the plant during
a fueling outage, and the plant had shut down, and
repaired the cracks in accordance with the regulatory
requirements prior to bringing the unit back to power.
But since the industry had recorded some
degradation in their nozzles in 1997, we issued a
generic letter and asked the industry what their plans
were for inspecting the vessel heads of the remaining
plants in the industry.
Basically what happened is that the
industry came back to the NRC and added a number of
plants to their volume inspection list, and a number
of them included one of the facilities at the Oconee
Nuclear Plant.
They did their volumetrics, and recorded
the occurrence of some very shallow cracks at that
unit, but they were not deep enough to be a safety
concern at the time.
In addition the industry only proposed
that they were going to proposed that they would
continue to perform visual inspections of the vessel
heads at each refueling outage for teach plant.
In 1999, the Oconee Unit One plant was
down for a refueling outage, and performed a visual
inspection of its head, and recorded the occurrence of
leakage on the vessel head, and did follow-up
volumetric inspections, and visual inspections to
ascertain how deep the problem was, and determined
that they did have some circumferential cracks in the
vessel head.
Excuse me, let me step back for a second.
For Oconee I, they did record some axial cracks, but
they did not record any circumferential cracks.
Later on, in February of the following
year, in the year 2000, the Oconee Unit III went down
for its refueling outage, and performed the same sort
of visual examination, and also detected leakage in a
number of the penetration nozzles, and did its follow-
up exams.
And during these follow-up inspections the
utility for the plant did record some occurrence of
circumferential cracking in a couple of the nozzles.
Now, circumferential cracking is
considered by the staff to be very safety significant,
because if it grows to a large enough size, it can
rupture the nozzle and lead to a failure, and lead to
a small loss of coolant accident for the plant.
Sine the cracking of Oconee Unit III was
so safety significant, the NRC continued its dialogue
with the industry, and asked the industry what its
plans were to perform more stringent inspections of
the remaining PWRs in the industry.
The industry came back with some safety
assessments, but the NRC did not quite concur with all
the conclusions in the safety assessment. So in
August of the year 2001, they issued a bulletin on the
issue, and requested what the plants were going to do
to inspect their heads, including volumetric
inspections of the nozzles, and the associated
attachment models.
As well as a visual examinations of the
vessel heads without any insulation on the heads. All
the utilities in the industry responded to the issue,
including Florida Power and Light, in September or
October of 2001.
And in Florida Power and Light's response
to the bulletin, it provided its program for
inspecting the vessel heads of the Turkey Point units
and the St. Lucie units.
Now we get to the relationship of the
bulletin to the application. Florida Power and Light
submitted their application for NRC review prior to
the issuance of the bulletin.
And since we had not come to our final
conclusions of the impact of the Oconee data on the
industry, we left an open item in the application
regarding taking our integrated program committed to
the industry's commitments on how to inspect the heads
to bring it up to speed with the latest reports
submitted by the industry, and with the NRC
recommendations in the NRC bulletin for inspecting the
vessel heads.
When the applicant responded to the open
items, they referred to the bulletin response as their
current basis of the program, and their bulletin
response indicated to us that they were going to
continue to participate in the industry program, and
update as necessary based on current future potential
events that would occur in the industry.
They provided a revised susceptibility
ranking for their vessel heads, and they also provided
their schedule for timely enhanced visual inspections
of the vessel heads on bare surfaces of the heads.
And in the response they also did an
analysis of the nozzles to determine whether if they
had cracking through the associated J-groove and
whether they would have leakage to the top of the
heads.
In their response to the bulletin, they
indicated that there was enough of a gap in the nozzle
designs that if they had a crack through the weld that
we could definitely be able to migrate to the top of
the heads, and leakage would be able to be detected.
Based on our review of the bulletin
response, and of the applicant's response to the open
item, we concluded that the aging management program
for the Alloy 600 penetration nozzles to the vessel
head would provide a sufficient basis for monitoring
and controlling stress corrosion in the muzzles.
And therefore we had included that was a
sufficient response, and continued to provide health
and safety to the public, and we decided that the open
issue was resolved.
CHAIRMAN BONACA: Now, one of the units
was inspected recently.
MR. MEDOFF: Right.
CHAIRMAN BONACA: And the other one is
going to be inspected now.
MR. MEDOFF: Right.
CHAIRMAN BONACA: So the inspection will
start when?
MR. MEDOFF: In a week, I guess.
DR. SIEBER: It might be good if the
applicant desires to tell us what the results of the
inspection was, and what unit it was.
MR. HALE: Yes. As Jim had mentioned, we
did a full qualified visual, and where we inspected
every penetration, and there was no evidence of
leakage.
And this is documented in quite detail as
each individual penetration. We are also planning to
do the same type of inspection, a qualified visual, on
Unit 4 during the refueling outage coming up in a week
or so.
DR. SIEBER: Thank you.
CHAIRMAN BONACA: Now, I would like to ask
a question. What are the next steps? What is the NEI
program foreseen for plants that are inspected, and
have no findings?
MR. COLLARD: My name is Steve Collard,
and I am the supervisor of the Materials Programs
Group in our engineering division up in Geno Beach.
Right now what we are anticipating doing is following
the code.
The code is on this and -- the ASME code
is working on a program of inspection schedules, and
it looks like we will be doing something like that
inspections like once period, three times in 10 years,
and perhaps once every refueling outage, and that is
undecided.
We are doing some debating about that, and
depending upon its susceptibility, and where you are
you, and what material you have, and whether you have
a new one or not.
And that is how we are looking at the
continued inspections. We are also starting to
evaluate replacing the reactor vessel heads, but we
are really early in that. However, we are following
the industry, and following every inspection.
CHAIRMAN BONACA: Well, several plants
have already committed to replacement if I understand
that correctly.
MR. COLLARD: Yes.
CHAIRMAN BONACA: So that is an option
already chosen by some of the high susceptibility
plants. I wold expect that you would be looking at
the frequency of inspections, and addressing the --
MS. ABBOTT: Yes. I think in summary --
this is Liz Abbott from Florida Power and Light. Our
commitment is to continue to follow issues as they
develop, and we are performing the inspections, and
obviously we have completed one unit.
And the second unit will be taken off-
light in about 9 or 10 days for its scheduled
refueling outage, and we do have the same inspection
plan for that unit.
We have not identified any issues on our
heads that need to be addressed. So at this point, we
are monitoring the developments from other members of
the industry, and reviewing that data, and reaching
the conclusion on what is most appropriate for our
units.
I would also like to emphasize that we
maintain very stringent controls for primary side
leakage, and we do have extensive leaking inspections
and a zero tolerance for evidence of leakage, which is
normally seen through boric acid buildup, all on our
primary side and non-soluble components.
And I think we are probably in the upper
echelon so to speak of the industry when it comes to
our programs and acceptance criteria, and so forth,
that we maintain as part of our maintenance programs,
and are continued through our boric acid leakage
identification program commitments under the renewal
term industry-wide.
So I think there is two aspects that you
look at here, and I think you have to look at the
commitment to both programs, both of which are
included as part of our commitments under the renewed
license.
MR. GRIMES: This is Chris Grimes, and I
will try and put a wrap around it. I would remind you
that last year when we came to describe the results of
our Arkansas license renewal review, at that time the
results from the Oconee inspections were fresh, and
caused a bit of a stir.
That bit of a stir was a bulletin that
caused all plants in response to Bulletin 2001-01, to
go out on an accelerated basis and start gathering
more information about nozzle cracks, and control rod
drive nozzles, and their attachments, are the area of
interest, in terms of where this cracking occurs.
And the susceptibility -- and not just
Alloy 600, and that is the name of the program, but it
is also the associated weld materials. The results of
those tests are still coming in, and as you know, and
as you have seen in the notifications, there was some
significant findings that now have to be folded into
the NRC's assessment, and into our judgments about
what additional changes are needed in the inspection
and repair practices for vessel heads.
This is not much different than evolutions
that we have gone through in understanding the causes
and inspection controls for steam generator tubes,
which is another material problem that relates to the
high temperature chemistry reactions in the reactor
coolant system.
So this is very much a process that --
well, that the ongoing regulatory process, and the
experienced feedback to identify how the maintenance
and inspection activities need to be involved.
And as James said, this is a program that
is learning and evolving, and correcting as inspection
findings come up. And we expect that it will continue
to do so by virtue of the applicant's commitments to
continuing to rely on those industry programs.
And it was on that basis and it was that
commitment that formed the basis for our conclusion
about the adequacy of the aging management attributes.
CHAIRMAN BONACA: Well, we may know
something about these plants and the inspections when
it comes up in the meeting in April. That will be
interesting, and I am pleased to hear that the first
inspections were negative.
MR. MEDOFF: And I would like to point out
that the industry does consider this integrated
program to be a living program, and NEI has repeatedly
talked to us, and told us, and informed us that NEI
would update the program pending all cracking events
and further studies that NEI or the materials
reliability program would conduct.
So based on that type of information, we
considered this open item to be resolved.
CHAIRMAN BONACA: Okay. Now, if I
remember, the Alloy 600's nozzles are the only
components having Alloy 600 in the Turkey Point Plant,
right?
MR. MEDOFF: Yes, this is a Westinghouse
design, and the Alloy 600s are only on the head. In
contrast to some of the CE and BMW plants that have
Alloy 600 nozzles to either of the pressurizers or the
steam generators, or the hotlegs.
MEMBER SHACK: This is also an unusual
Westinghouse plant that doesn't have any Alloy 182
butter on the primary piping. They are a Framatone
plant.
CHAIRMAN BONACA: That's good to know.
MEMBER SHACK: Yes, they are like this.
They use stainless steel. The French have no Alloy
182.
CHAIRMAN BONACA: Yes, that's good to
know.
MR. MEDOFF: If there are no further
questions on the Alloy 600 program, I would like to
continue with the open item on reactor pressure vessel
underclad cracking.
Thee is a potential issue with the PWR
industry on developing cracking in the faradic portion
of reactor pressure vessel at the interface where the
faradic portion meets the austenitic stainless steel
cladding.
Basically whether the issue is considered
by the staff to be prevalent or not really depends on
the fabrication practices on how they fabricated the
vessel, and Regulatory Guide 1.43 really goes into
detail on how the cracking could potentially develop.
It talks about the fabrication practices
that lead to it, and so therefore I am not going to
get into the details on this, because the regulatory
guide talks about it in sufficiency.
However, since this is a potential issue,
the staff issued an RAI on the issue to the applicant,
and it must be stated that the Westinghouse Erector
Company submitted a WCAP report that provided its
analysis for potential underclad cracks to grow by a
thermal fatigue mechanism and grow further into the
portion of the vessel and to create a safety concern.
Basically what the WCAP did was evaluate
the plants based on their number of cycles, and their
transients, and performed a fatigue analysis
consistent with the code requirements.
And made a general conclusion that it
wasn't an issue, but since we didn't have any
information on whether the plants applying for renewal
would have -- whether their fatigue cycles that they
have on record for the plant would bound the analysis
set forth by Westinghouse.
We issued a set of RAI open item
combinations, and basically for three unit
Westinghouse pressurized water reactors, of which
Turkey Point is part of that type of design, we
concluded that they would be bounded by the analysis
of the report, and could conclude that growth by
fatigue was not an issue if they could demonstrate
that the number of cycles analyzed in their report
were bounding for the plant.
In addition, we issued an open item
portion of that, and that once a response came back
from an applicant to respond to the RAI, that they
could show that their time limited aging analysis for
this type of fatigue growth would be similarly
described in the updated final safety analysis report
for the plant.
So basically we did that for Turkey Point,
and we issued an RAI regarding the issue to them.
They responded to us and demonstrated that they were
bounded by the reports. So we closed out the request
for additional information on that portion of the
item.
And then we kept an open item to confirm
that they were going to put the time limited aging
analysis into the updated final safety analysis for
the report.
This is really a record type of keeping
type of open item. The applicant responded in kind
and did confirm that they did put the time limited
aging analysis into the updated final safety analysis.
We considered this to be sufficient, and
considered that the open item was resolved.
DR. SIEBER: The in-service inspection
requires that a licensee every 10 years do an in-
service inspection using ultrasonic means for the
reactor vessel, and it is done from the inside of the
vessel through the clad and to the area in the faradic
structure where these deep cracks would form.
My question is will the in-service
inspection identify these fatigue cracks if in fact
they do form over so many cycles, or so many thermal
cycles?
MR. MEDOFF: Not being the expert on this,
I would like to have someone from Region One who is
more familiar with the issue.
MR. GRIMES: Is there anybody on the phone
who has an answer to that question?
MR. ELLIOTT: This is Barry Elliott. The
in-service inspection, the NEI inspection is an
inspection of welds, and the concern here is not the
for welds. The concern here is for the base material.
The only area of the base material that
would be inspected is like a half-an-inch or an inch
on either side of the weld. And I just don't think
that these flaw are going to be found.
These are very tiny flaws that are on the
order of a tenth to three-sixteenths of an inch when
they started. They don't grow very much, and the
basis for our accepting this is not the ultrasonic
inspection.
It is that the flaws grow only a very
small amount and based on the side of the flaw, we
don't really need to do any additional inspection.
The structural integrity is ensured by the analysis
that the growth of the flow is strong enough that all
the safety versions of the ASME code are still
satisfied. This is Barry Elliott.
DR. SIEBER: Thank you.
MR. MEDOFF: That you, Barry. Are there
any further questions on this issue?
CHAIRMAN BONACA: I see the next issue is
the last of the four issues raised by public citizens,
and I would propose that we take a recess for 15
minutes, and then we address these issues together
after that.
But before we do so, however, I would like
to ask Mr. Smilan if he has any additional comments
that he would like to make with regard to these open
issues or open items?
MR. SMILAN: Offhand, my concern stems
from the fact that I am a member of the National
Association of Atomic Veterans, and I am also a
disabled veteran.
I was operated on for esophagal cancer a
year ago, and there is a law on the books, and it is
a Federal statute, and it is called the Radiation
Exposed Veterans Compensation Act, which actually
provides a presumption that if you were on-site at
Bikini or Anyweektoch (phonetic), which I was back in
1954, that exposure to the atmospheric tests there was
the cause of 21 categories of cancer, and if you could
track one of them, then you qualify.
The law was amended two years ago, in
2000, to include civilians, and that Act is now known
as the Radiation Exposure Compensation Act, and that
one is administered by the Department of Justice.
And it provides compensation for people
who are on-site when those tests at Yucca Flats and
the Alusions, and people who were downwind of this, as
far as Las Vegas, from the Yucca Flats tests.
The reason that I am giving you this and
how it relates to the FDL is this. The Act covers
people who are engaged in mining uranium ore, loading
it, and transporting it.
Those workers are actually covered by a
program administered by the Labor Department now.
Florida Power and Light has been disingenuous to say
the least in the way that they presented nuclear power
to the public in this area.
At their St. Lucie plant up on Hutchinson
Island, they have a museum there. I don't know if you
people have visited it. Have you visited that museum?
CHAIRMAN BONACA: I have not.
MR. SMILAN: They bus school children in
there and they portray to them people pushing shovels
and mining yellow cake, uranium ore, with no
protective clothing, and no protective breathing
equipment.
I spoke to a gentleman this morning who
was in the Army at Yucca Flats, and he told me this
morning that he had not been provided with protective
clothing, or protective breathing equipment, and that
the AEC people who were on site did have that kind of
equipment.
When I was at Bikini, and was detailed to
run Jalapi Atoll, which was subjected to radioactive
fallout, I was not furnished with protective gear or
breathing equipment.
Now, these children who were taken up to
Hutchinson Island, school children, and shown this
exhibit, see people mining uranium ore as if it were
a totally safe material to handle.
There was also an illustration -- and I am
sure that the FDL is going to remove it just as
quickly as they can, showing someone wearing a white
three-quarter length coat, supposedly a technician,
someone with a scientific background, holding a
capsule with uranium pellets that are components of
fuel rods, and holding it in their bare hand.
And that is the misinformation that FDL
has actually been giving out to the public here. I
wonder if the people responsible for that realize what
the significance of this type of propaganda is on
children.
Plutonium is supposed to be the most
deadliest substance on the face of the earth, and I
have read literature that says that one-one hundredth
of the amount required to cover the head of a pin is
sufficient to give you cancer.
Now, I am told that I have a 40 percent
chance of survival for five years, and there is a very
good chance that my cancer is related to what I got as
a result of that exposure.
And that is my motivation for coming here
and for my having been involved in opposition to the
opening of the Schorum Nuclear Power Plant, which as
you know was never opened.
And I doubt that these people today could
get a siting permit for this plant here in Homestead,
22 miles south of Miami, especially with the
geopolitical situation we have the terrorism on a
rampage.
And let me also mention this fact, because
I think it is significant. The second largest Jewish
population in the United States is situated here in
South Florida, on the southeast coast.
And it used to be Los Angeles, and now the
second largest Jewish population is here. This is a
very prime area for attack. And not to become
paranoid about it, but FDL issued a press release in
conjunction with FMG when they were supposed to
consolidate their operations.
And which would have made them the second
largest operator of nuclear power plants in the
country, and the largest generator of nuclear power in
the country.
And in that press release, they spoke of
allowing a firm -- the name escapes me at the moment,
but allowing a firm whose parent company was situated
in South America, to handle their spent nuclear fuel
roads, which is stored on-site as you know, and to
transport them to Europe, where they would be
reprocessed either in Belgium or in France. Cogema I
think is the name of the firm.
And just the mere fact of letting those
spent fuel rods out of the country, and allowing
foreign nationals to have access to it I think poses
such a significant threat to this country.
And I think the FDL was irresponsible in
even making that type of a proposal. There was one
Caribbean country that objected to spent nuclear fuel
rods being transported from Japan through the
Caribbean here to get to Europe so as to be
reprocessed.
And now as an airline pilot who has flown
to South America, I can tell you that if you drop a
plum line from Miami directly south, it hits the
Panama Canal.
So to get those fuel rods from Japan to
Europe, they are coming through the Panama Canal, and
we are setting ourselves up for something really big
here to happen.
And as you know, these terrorist
organizations met, and they are trying to get their
hands on nuclear material to make their dirty nuclear
bombs.
And we have got a real potential problem,
especially with the influx of population that is going
to gravitate down to this area. Hey, guys, I will
tell you, be Americans and do the right thing here,
and slow down, and get some responsible rebuttal in
here.
Because as I said before, I don't doubt
the sincerity of people in this room. I have friends
who hold degrees, one of them, in nuclear physics.
The guy is a doctor.
And he told me that an airplane cannot fly
in one of these things and destroy it. Well, we saw
something a little different here with the World Trade
Center, and when those planes hit that building in
excess of 500 miles an hour.
I used to fly 747s from San Francisco to
Hong Kong, and to Seoul, and do you know that the
airplane was 300,000 pounds lighter when it landed,
because that is how much fuel we consumed. The fuel
was kerosene.
The reason that we used kerosene instead
of gas was because it generates more btu's. So you
have got the dynamite right there. And Florida, and
down here in Miami, you have this International
Airport that is looking to double the amount of
international travel.
And when those airplanes take off and
going down to deep South America, two-thirds of the
flight is over the Amazon, and those things are loaded
to the gills with fuel.
You have got a real hot spot down here,
and you had better tread gently, and the credibility
of the Nuclear Regulatory Commission I think is also
at stake if you allow that plant to be relicensed and
get an extension.
And you don't have responsible intervenors
in here, and just one last final though. I started
out flying helicopters in the Air Force. I flew fixed
wing helicopters, and they used to take the blades
from the H-13s and throw them away after twelve
hundred hours.
That was the service life of that, and it
was 2,000 hours on the Corsica H-19, and they used to
throw them away, and that is an expensive item. And
the reason was that you flex those blades so many
times that that metal is going to crystalize.
And the same thing happens when you
pressurize an airplane, and every time you pressurize
it, and believe me when I say aviation is just replete
with failures and nobody is flying old airplanes.
You are not going to put your family on a
747 that is 28 years old, or at least if you know
about it, you are not going to do it. So I think
these same concepts ought to apply to what we are
doing here with nuclear power plants, because I think
it is a bad scene. Thank you for your time.
CHAIRMAN BONACA: Thank you for your
comments.
MR. GRIMES: Before you break for a
recess, and this is Chris Grimes, I would like to ask
if there are any specific questions about the
technical matters that we addressed today?
I would like to take advantage of the
staff that we have on the phone, and if there aren't
going to be any more questions about the specific
technical aspects of the issues that we have
addressed, I would like to turn them loose and have
them go back to work on other things.
CHAIRMAN BONACA: Are there any questions
regarding technical issues on these four items?
(No audible response.)
CHAIRMAN BONACA: Well, they will be
presented again in April, and we don't have any
additional clarification needed at this time. So we
can let them go. And with that, let's take a recess,
and come back at 3:25.
(Brief recess.)
CHAIRMAN BONACA: The meeting is called to
order again, and we are now proceeding with a
discussion by the staff of comments from the public
citizens. All right. Please state your name.
MR. MEDOFF: This is Jim Medoff with NRR
once more, and right now we are going to discuss some
of the comments that were submitted to us, and in Mr.
Oncavage's letter that was recently submitted.
Basically, when we looked at the four
concerns submitted by mr. Oncavage, we basically
isolated them into four broad-based areas, the first
being the effect of voids on aging degradation rates,
and the structural integrity of containment
structures.
The second broad based category being the
effect of design basis for hurricane wind speeds, and
surges on safe operation of the facilities.
The third being the effect of terrorist
attacks on safe operation of the facilities, and the
third regarding the Turkey Point Spent Fuel Capacity.
In regard to the effects of voids on aging
degradation rates, and the integrity of the concrete
containment structures, we don't quite agree that the
voids will have any effect on the aging rates.
We consider them to be intrinsic thermal
dynamic kinetic properties that are not a function of
amount or volume, or surface area. While we do agree
that if you have more voids for any given aging
degradation rate, you might come to a certain level of
degradation more quickly.
We don't consider them to have any effect
on the aging degradation rates. And with respect to
the testing for the structural integrity of the
concrete containment structures, Florida Power and
Light has proposed an ASME Section IWL in-service
inspection program to monitor for aging of the
concrete structures.
And they consider the concrete structure
components to be within scope of license renewal.
This is the same IWL program that that NRC oversees
through Regulation 10 CFR 50.55(a), and that is
referenced in your technical specification
requirements.
The applicant has periodic surveillance
requirements for leak rate testing and structural
integrity testing in accordance with the IWL program
in their technical specifications.
The technical specifications, and/or the
IWL in-service inspection program, can dictate the
frequency of these examinations, and that the
applicant implements according to the specified
frequencies.
We consider that the safety of the public
and safe operation of plants will continue to be
assured through the implementation of the proper
technical specification, and the proper ASME IWL
service inspection program requirements.
And we consider those to be sufficient to
test further the integrity of the containment
structures.
CHAIRMAN BONACA: This morning, there was
an interpretation we had of the plant. I asked a
question regarding the genetic implication to other
designs, where the presence of rebar on the structure
there that caused also voids in other similar plants.
And the answer was not available because
it would historical and it would now be 20 years old.
I would suggest that if you have any information on
that that you would have it available for the April
meeting.
MR. MEDOFF: At that time, I will bring it
up with the mechanical engineering branch of NRR, and
determine whether they have any data on it, and
whether they consider it to be a generic issue, and we
can get back to you on it.
CHAIRMAN BONACA: I would expect that the
issue would be addressed then. So therefore it would
be historical information to the committee, but I
think it would be appropriate to just if you have any
information on that.
MR. MEDOFF: Okay. I will check with
EMAD.
CHAIRMAN BONACA: Thank you.
MEMBER KRESS: I realize that it is mostly
irrelevant for license renewal, but can I ask if there
are any implications with respect to LERF?
MR. MEDOFF: That is an area outside my
expertise. So I would refrain from commenting on
that.
MR. GRIMES: This is Chris Grimes. I will
only comment to the extent that I am able to comment;
that there is an aspect of -- you said LERF, and the
release rates and the release probabilities include
consideration of containment failure rates.
And to the extent that there is implicit
in the integrity of the containment and its failure
some margin for construction defects or failures of
the liner, I would say that there is an allowance
there, but not an explicit consideration of this
particular kind.
MEMBER KRESS: Well, when one runs the
PRA, you get a LERF, and it is better to use design
pressure other than to say that the actual failure
pressure is somewhat higher than that.
And that somewhat higher is estimated, but
you can estimate it based on some sort of hot element
calculations if that can be done, or it is based on
experience, or other things.
But I think they assume in that estimate
that the containment is fairly structurally sound, and
I don't know if they used the right success criteria
in the PRA to decide on when you get a LERF.
MR. GRIMES: And all I can remember about
the containment failure models is that there is a
distribution about the failure of the containment that
has an uncertainty associated with it.
So there is even a probability that the
containment can fail at pressures below its design
pressure.
MEMBER KRESS: Yes.
MR. GRIMES: Those are much smaller
probabilities. The probability of containment failure
goes up and reaches the median or the mean point, or
whatever is statistically appropriate for LERF, the
large early release frequency that has implicit in it
this margin or uncertainty band that provides for all
kinds of uncertainties.
And those include structural capability or
failures that were unanticipated because of
construction defects.
MEMBER KRESS: I am concerned about that
whole distribution has shifted.
MR. GRIMES: I understand.
MR. MEDOFF: If you would like, we can
talk to people that are more familiar with it, RAD
protection and/or the PRA branches.
MEMBER KRESS: I think this is a PRA.
MR. MEDOFF: If there are no further
questions on the structure integrity for the
containment structures, I will go on to the next
category, which is the effect of design basis on
hurricane wind speeds and storm waves on safe
operation of the Turkey Point facilities.
Basically, I independently reviewed the
design bases for the plants, and also contacted the
NOAH of the U.S. Department of Commerce to get more
familiar with the wind speeds and the height of the
storm surges on the Atlantic Coast.
Basically NOAH records that the maximum
wind speeds and surge heights ever recorded for
Atlantic Coast Category 5 hurricanes as been on the
order of approximately 160 miles an hour, and that
wind speed puts it into a Category 5 hurricane, and 20
feet respectively.
The highest wind speed was recorded for a
Category 5 hurricane that occurred in 1935 in the
Florida Keys, and the highest surge height that has
been recorded for the recent hurricane, Hugo, which
hit the North Atlantic Coast, and that was recorded at
20 feet.
The current licensing basis for Turkey
Point indicates that structures housing safety related
equipment Seismic I category structures are designed
to withstand wind speeds and surge heights that were
ever recorded for Category 4/5 hurricanes.
So we consider it a less further technical
information submitted to us that indicates otherwise,
and we consider the current design basis for the
facilities to be capable of handling the Category 5
hurricane effects.
MEMBER KRESS: One of the specific
concerns was the spent fuel pool.
MR. MEDOFF: Right.
MEMBER KRESS: Does that include the spent
fuel pool?
MR. MEDOFF: When I checked the design
basis the spent fuel pools are in the auxiliary
buildings, and they are classified as Seismic I
structures. Any further questions on this issue?
If not, I am going to bypass the third one
for the last item, the effect of terrorism, and I am
going to talk about the spent fuel capacity. And the
technical specifications for the plant require a
minimum and specify a maximum allowable fuel for
storage capacity for the spent fuel rods.
I'm sorry, but I am getting ahead of
myself. Let me talk about electrical system
capability. One of his concerns dealt with emergency
diesel generators storage capacities. I apologize.
The technical specifications for Turkey
Point require them to keep a minimum inventory in each
of the refueling water -- not water, but diesel fuel
storage tanks.
One of the concerns for Mr. Oncavage
identified that the plant had been unavailable for
further service from the outside during Hurricane
Andrew, and he was concerned that the diesel fuel
would be used up, and they wouldn't have any emergency
diesel generator capability to mitigate the
consequences of an accident.
What I will say is that Turkey Point has
the capability of delivering fuel on site if necessary
by barge, or by airplane, or by airplane, or by
alternate road routes, or highway routes, to the
plant.
And they consider that they are capable of
maintaining emergency diesel generator fuel supplies
for the plant so that they can maintain safety at the
facilities.
We feel that any technical specifications
on the emergency diesel general fuel storage tanks and
they capability to deliver fuel from off-site is
capable to ensure the integrity of the plant.
DR. BARTON: Did you say you have a
committed supplier to deliver this fuel should you
need it?
MR. MEDOFF: That I am not sure of. You
would have to
DR. BARTON: I thought I heard that this
morning.
MS. ABBOTT: This is Liz Abbott from
Florida Power and Light. As part of our hurricane
preparations, we will normally top off our tanks or
verify that they have been topped off recently.
And we also typically contact our vendor
and make sure that we are on their priority list for
providing fuel, which is normally not an issue with
them.
So we do maintain contact with our regular
fuel supplier and we are considered a priority
customer for them.
DR. BARTON: But my question was though is
it possible if this vendor gets wiped out in a
Category 5 hurricane?
MS. ABBOTT: I am not familiar with their
facility. Let's just postulate that it is.
DR. BARTON: That's what I am getting at.
MS. ABBOTT: And certainly a hurricane
would affect a limited area, and there is no reason
why we couldn't go outside of that area and go to the
next supplier in line.
The fuel is not something that generally
is not available, and it certainly is capable of
fueling our diesel generators and having them perform
acceptably.
MR. MEDOFF: Any further questions?
CHAIRMAN BONACA: I don't want to pursue
that any further, but there is a tech spec
requirement, right, on the diesel fuel supply?
MR. MEDOFF: Yes.
CHAIRMAN BONACA: And so that is a text
book requirement that there will be a certain amount
of fuel on-site anyway.
MR. GRIMES: This is Chris Grimes, and
harkening back to a former life, there is provisions
for the supply in the day tank, but also the reserve
tank, and the quality of the fuel in the tanks.
The technical specifications include a
number of tests to verify the quality of the fuel that
is maintained on-site.
CHAIRMAN BONACA: And it seems to me that
the tech specs specifically focus on a seven day
supply.
MR. MEDOFF: My recollection is that it is
a seven day supply, a seven day supply for each
diesel. I would have to go back and check, but I
believe that it was for each diesel.
CHAIRMAN BONACA: So that can be extended
quite a bit with appropriate monitoring.
MR. MEDOFF: We feel they feel that they
have enough time to get back on site so they can
maintain operation on generators. I am going to
bypass the terrorist concerns and discuss the spent
fuel cooling system reliability for Mr. Oncavage.
The spent fuel pools and cooling system
are housed in safety related structures that are
designed to withstand the consequences of a category
five hurricane.
The technical specification and design
requirements control the amount of storage at the
facilities, and they have to take action before they
exceed the maximum storage limits.
10 CFR Part 51 treats spent fuel issues as
Category One issues and considers them to be current
licensing issues, and therefore outside the scope of
license renewal.
We feel that the design basis, there
really aren't from what we can see any safety issues
with the spent fuel pool at this point. And then
finally Mr. Oncavage, in two of his issues, brought up
potential safety issues with terrorist attacks on the
facilities.
I have to state that right now the
commission has assigned a special task group to look
into this. It is classified material, and we were not
even permitted to talk about it at the agency for
those that are not dealing with it in their branch.
But the Commission is definitely looking
into the safety issues of terrorist attacks on the
industry, and Florida Power and Light, and the Turkey
Point and St. Lucie units will be part of that study.
I'm sure when they declassify the
information that the commission will make it available
to the public for review. But they are looking into
the generic safety issues with regard to terrorist
attacks on the industry.
MR. GRIMES: This is Chris Grimes, and I
would like to add that there is a theme throughout Mr.
Oncovage's concerns that really get to the safety of
the facility, irrespective of license renewal.
The questions about plant vulnerabilities
and overall plant safety. We did struggle with trying
to achieve public confidence in the process.
At the same time that we say we can go
public with the license renewal decision, while we are
dealing with some of these issues, like terrorist
attacks, at the regulatory information conference, the
commissioners talked about the anticipated changes in
the design basis threat and the threshold that
distinguishes between the plant's responsibility to
defend against terrorists and the nation's
responsibility to declare an act of war.
That distinction between the
responsibilities of the Nuclear Regulatory Commission
and the Department of Defense have now come into play,
and we expect that there will probably be legislation
that will provide the NRC with guidance on the
security issues.
That is really the heart of the license
renewal process; an ability to rely on the ongoing
regulatory programs to decide what changes need to be
made for safety standards today or tomorrow, or next
year, or 20 years from now.
And our ability to look outside of those
issues and simply concentrate on aging effects, and
the science of maintenance and inspection of the
facility.
And Mr. Oncavage was not satisfied with
that explanation, and we can understand and appreciate
that, but that was the basis upon which the Atomic
Safety and Licensing Board, and the Commission
concluded the hearings were not warranted on these
issues because they are issues related to the adequacy
of the plant safety.
And not issues related to the scope of our
review of aging management programs.
MR. MEDOFF: I am going to return the
microphone to Dr. Auluck for further comments.
MR. AULUCK: The next item we will discuss
is the inspection report, but before we do that, I
would like to make a statement. The Commission in
their order specifically stated that if Mr. Oncavage
generally knows of a current safety problem resulting
from a design of the Turkey Point facility, he should
petition under 10 CFR 2.206 for action on that
license.
MR. JULIAN: My name is Caudle Julian with
the Nuclear Regulatory Commission, and my first name
is Caudle, C-A-U-D-L-E, and I am with the NRC out of
Atlanta, Georgia.
And I was the team leader for the
inspections supporting license renewal at Turkey
Point, and have been on several others before, and am
continuing to do that work now.
At Turkey Point, our first inspection was
what we call the scoping and screening inspection,
where we are looking at the results of their efforts
to determine what plant equipment needs to be
considered for aging management measures.
We reviewed their engineering basis
documentation for the results that they have achieved,
and they have got a lot of it. The documentation that
we found was of good quality. It was detailed,
thorough, and understandable.
We examined a substantial portion of the
plant safety related equipment, and our inspectors
have assigned systems, and have them go out with the
plant engineers and walk about the plant, and look at
the examples of the plant safety related equipment,
and see what condition it is in today.
We concluded the material condition as we
observed it was good of the plant overall, and had no
significant negative findings in looking at plant
equipment.
And in our inspection conclusions on the
scoping and screening inspection, we are essentially
consistent with the NRR audit that was performed
earlier on the process for scoping and screening.
So we moved on to the second inspection,
which was of two weeks duration. The first one was
one week. The second was of two weeks duration.
And there we looked at aging management
programs, and we reviewed the results of existing
plant programs that are accredited as becoming aging
management programs on downstream.
We concluded that the existing aging
management programs are being implemented as they
described in their license renewal application, and as
we reviewed the plans that they have for new aging
management programs, and also for the enhancement of
existing programs, and we concluded there that the
plants are consistent with the commitments that they
made in the license renewal application.
During the second inspection, we looked at
plant equipment to try to cover as much as we possibly
could, and again had no negative conclusions. We
thought that the plant equipment was in good
condition.
And after we had concluded the second
inspections, we determined that we really didn't need
a third open items inspection for this plant because
everything was pretty much resolved and taken care of.
FPL took extraordinary measures to respond
to questions that we had, and we thought that
cooperation and forthrightness was excellent. And
after running these issues over with our management in
the region, and our regional administrator, the
regional administrator has signed the inspection
completion letter on February 1st, 2002.
So that letter concludes that Region Two
is complete with our inspections, and satisfied with
the results. Are there any questions?
DR. SIEBER: I guess I would like to make
a comment, in that I reviewed the documentation and
particularly the drawings, which ended up in
headquarters and available to us, and I thought that
was an asset to us to be able to look in advance and
understand what the licensee had done in these cases,
and to look how the markups and the drawings, and the
scoping generally went. And so I appreciate that
myself.
MEMBER KRESS: Are your inspectors trained
in what to look for license renewal and do they have
guidance documents?
MR. JULIAN: Yes, they do. We have the
inspection manual chapter, which is a high level
document, Manual Chapter 25.16, and a more detailed
inspection procedure, 7100.2, for doing license
renewal.
But more and more I am using the same
inspectors, and they are gaining experience on the job
more and more, and so they know more and more what to
look for at each plant that we go to.
MR. GRIMES: I would like to add -- and
this is Chris Grimes -- that for each plant this group
of more and more experienced folks put together plant
specific inspection plans, where they gather insights
from the reviewers and headquarters about targets of
opportunity, particular areas to inspect, and that
plant specific inspection plan provides further
guidance to the inspectors on how to achieve a good
inspection.
MEMBER KRESS: Do you guys review that
plan?
MR. GRIMES: Yes, sir. The inspection
plan is actually issued jointly by headquarters and
the region to the regional division director and me.
We get direction that is a cooperative effort between
the technical review staff and the NRR and the region.
MEMBER SHACK: When you read the license
renewal application or even the updated FSAR, there is
always this question of level of detail, and the one
that I sort of focused on was looking at their leak
before break analysis, where the description of it was
perfectly reasonable. I didn't have any disagreements
with it at all.
The question was that with the aging of
the casting, and the steel elbows, and components,
whether that would affect the leak before break
analysis that they did.
And so let's say they assumed the maximum
possible aging thing, all the words were right, but
there was no number anywhere, or no clue as to where
they picked, or how they picked the fact for toughness
for the aged cast stainless.
Now, would that be something that would
come out in the inspection that presumably somewhere
back at the plant somebody had some data? Would that
be expected?
MR. JULIAN: Probably not. We don't get
into that detail here in our inspections. We are
trying to focus on the plant equipment and the aging
management programs, and that is a review issue that
would be handled by NRR technically.
MR. GRIMES: And I will answer that
question in two ways. The first way is probably not
in the inspection, unless Barry Elliott thought that
the inspectors could find it in a different place, and
than he could draw it out during the course of the
staff's review of the cast program.
MEMBER SHACK: Well, even if there was a
reference to the EPRI document, or something, but
there was no reference in either the SER or the FSAR,
or the license renewal application that I could find.
MR. HALE: Steve Hale, Florida Power and
Light. For something to be at the FPL, it has to be
incorporated, and one of the criteria is that it has
to be currently in your current licensing basis.
And that means that it is in the SAR and
it is in certain locations. So when it comes to leak
before break, considering that it was part of our
current licensing basis, there are -- there is
information in the SAR relative to what was approved
previously for leak before break.
Now, in terms of what we included in the
application, we typically would include what we would
include if we were submitting a SAR update to that
existing analysis.
So we basically -- so there is information
in the SAR. I think if you went to the SAR, you would
find a description, a more detailed description.
MEMBER SHACK: Well, I got the update of
the SAR and I went there.
MR. HALE: That is the license renewal
summary.
MEMBER SHACK: So if I go to the full SAR.
MR. HALE: In the SAR itself, you will
find a summary of leak before break. What we were
addressing in license renewal was one, the impact of
extending the 20 years, and secondly, we don't collect
all those things that we call TALAs in one location.
So we put them all in one location so you
know what we define as TALAs for the license renewal
period.
MR. GRIMES: That is a very important
point that one of the reasons that the applications
are now becoming packaged with the latest version of
the updated plant and safety analysis report is that
there are details in there that constitute a part of
the maintained current licensing basis.
And that are in some cases on the CD's
hyperlink, and so you can go back and find additional
details, but the FSAR supplement submitted with the
license renewal application is only the additional
commitment, or the additional detail of program
descriptions that is going to be added to that current
licensing basis to produce the new licensing basis.
MEMBER SHACK: Well, it is a contrast.
When you do vessel embrittlement, everybody refers to
Reg Guide 199 and we all know what numbers we are
dealing with.
When they dealt with environmental effects
on fatigue, they referred to NUREGs, and we all know
that the NUREGs by heart by now. But when I came to
CAS stainless, I couldn't find a reference to anything
anywhere.
MR. HALE: Part of that was a previous
license amendment that we had submitted to incorporate
leak before break into our current licensing basis.
So we were simply updating it for license
renewal. Whereas, the existing analysis, like those
kind of parameters and assumptions associated with
them, were already there. I don't know if that helps.
MEMBER SHACK: Well, I still think you
need more detail. You tell me that you use DOR to
calculate the neutron -- you know, I get all sorts of
information on the vessel embrittlement, and this
other one, you know, I get the post card.
And I have no real problems with it. I
really know what data you use, because there is only
really so many sources of data out there. But it just
seemed like it called out for a reference.
MS. ABBOTT: Just a little bit about --
this is Liz Abbott from Florida Power and Light, but
a little bit about the level of detail that is at the
site, and part of the question was did the inspection
team look at it.
We did prepare internally a document that
summarizes our determination of what constitutes time
limited aging analyses, and a summary of how we
address those TLAAs that generated the -- it is
basically a source document that generated the
application sections that you read.
That document was made available to the
inspection teams and the audit teams, and is a cross-
reference document that they used occasionally for
sample checks when they reviewed aging management
reports.
For instance, with the aging management
report that they were reviewing was on the reactor
coolant system, and if the reactor coolant system gad
some TLAAs associated with it, there would be a
summary of the TLAA in the aging management review
report for that system.
And it was up to the inspector if he chose
to then pull the string on that, and go look at the
TLAA report, which may then reference calculations and
things like that.
So I think maybe not categorically a
hundred percent as to the inspection team, because
typically you would not expect a hundred percent
inspection from an inspection team.
But I think you probably will find some
examples where they did look at some areas and posed
some questions. Whether it was that one in
particular, I don't recall.
MEMBER SHACK: Well, I should also agree
with Chris. I mean, I have full confidence that Barry
Elliott is going to beat CAS stainless steel
embrittlement to death. He just didn't document it.
CHAIRMAN BONACA: We had similar comments
from Dr. Ford before regarding the difficulty it is
for an independent reviewer like the ACRS to really
get fully inside the implementation that we get, and
we understand that. I mean, that is only a sample.
However, to the degree to which you can
make available through references, we really
appreciate it. It just that it is very important.
The other point that I wanted to make is something
that I have been talking about for a while, but I
can't go to the applicants to get it.
But I can go to the NRC to see if we could
get it, and again we have an application here that
comes in with a number of problems, existing problems,
and new problems, and that is really a snapshot in
time of what this application is all about.
Then comes the SER, and there we describe
a lot of negotiations and issue, or let me call it not
a negotiation, but simply a resolution of issues.
And added commitments that come to the
site because of that. We as a committee are not privy
to all the other information where these commitments
are made, and so I typically have to go through first
of all, all the commitments in the application.
Then I go through the SER and try to sort
out every additional commitment there is, and I cannot
say that I feel that I am complete. I cannot read
every single page and every single detail and point.
So what I am saying is that there it would
be worthwhile maybe in the SER, and at the end of it
there would be many a couple of pages summarizing all
of the added commitments coming as a result of the
resolution of RAIs, or open items.
It may be actually half a page, and maybe
just a third of a page, but I think it would be
helpful for a reviewer to then at the end reflect on
the application, and how it is modified by the
additional commitments, and that is just a suggestion.
I don't think it would be a great effort
on the part of the SCR responsible project manager,
but it is just a suggestion.
MR. MEDOFF: This is Jim Medoff with the
materials and chemical engineering branch currently on
rotation to the license renewal and environment impact
program.
We have summarized the open items and
confirmatory items in Chapter 1. The only thing that
we have not summarized is the RAIs. So if that is
what you are looking for --
CHAIRMAN BONACA: Well, again, I know that
there are license conditions that are listed at the
end and so that's there.
MR. MEDOFF: The other thing that we have
is we have referenced the sequence of correspondence
between the FPL and the NRC, and vice versa, in one of
the appendices to the FCR. So you can see that they
do make references to the RAI so you can get the
appropriate documentation.
MR. GRIMES: Dr. Bonaca, as my legacy, I
will leave behind a suggestion to the staff, that as
it looks at improvements in the style guides -- and by
which we intended the safety evaluation report would
be the compilation that you looked for.
It is very difficult to digest, and it is
not a stand alone document. It refers to the
application, the updated final safety analysis report,
the drawings, the inspection results, all of the
correspondence that as Jim points out is enumerated in
the appendix.
It is a daunting task for anyone to try
and digest all of that and have a real appreciation
for, well, what does it mean. It is conceivable that
there is a way as we look at streaming the safety
evaluation and making it more scrutable.
And also getting feedback from the ACRS
and others on the optimum form and content of the
application in a safety evaluation as it relates to
incorporating the generic aging lessons learned, we
will look for opportunities to find a place to sort of
summarize what are all of the programs.
I appreciate your vision, and we tried to
put together a little catalog of existing and new
programs. There are 30 some programs usually in total
that constitute something on the order of 400 to 500
procedures.
If there is a way to conveniently
summarize them, but we are still going to be referring
back to the updated final safety analysis report as
the compendium of the commitments.
CHAIRMAN BONACA: That is a regulatory
vehicle.
MR. GRIMES: And beyond that, I think that
it is not so important that you understand what
commitments were proposed and what commitments did we
end up with.
The process provided a means for us to
identify what is the necessary and sufficient basis
for the granting of a renewed license. And as I said,
if there is a way to more conveniently summarize that
to help the public appreciate what the result is, we
will see what we can do.
CHAIRMAN BONACA: I am not asking a big
effort, but I'm only saying there is a list, because
ultimately after I read the SER, I go back to the
application, and that has the tables with the columns.
And that really helps me understand and reflect on the
comments.
And it is just that I read it again and go
through it again, and that is not the whole story.
There is some stuff coming out of the SER. Here is
one thing and another one, and then I am left with
questions about how many I missed. So anyway it is a
minor comment, and it is not a major issue.
MR. JULIAN: That concludes my comments on
our inspection.
MR. MEDOFF: Mr. Bonaca, would it be
helpful if in the references if the documents at this
point should be in ADAMS if were to put associate
numbers by the reference so that you could enter ADAMS
and pull the documents for review?
It seems that the issue that I am getting
from you is that you are a little bit uncomfortable,
because sometimes you don't get to see the whole story
issued by the RAI.
MR. GRIMES: We did not intend to threaten
the ACRS. This is Chris Grimes.
MR. MEDOFF: We will brainstorm some ideas
with you separately.
MR. AULUCK: And to bring this to the last
item in our presentation, conclusions. The staff has
completed its review of the Turkey Point License
Renewal Application, and all the open items have been
resolved.
And the applicant has met the requirements
for license renewal as required by 10 CFR 54.29. At
this time, I will request the Committee's views on
whether or not there is anything additional we need to
do before preparing a recommendation to the
Commission.
And secondly, I would like your views and
recommendations, and input, regarding what topics or
subject matter you want us to focus on in next month's
ACRS full committee meeting.
CHAIRMAN BONACA: I first will go around
the table and see if there are any questions or
additional issues that the members would like to
raise. Jack.
DR. SIEBER: No, I have none. I thought
that the staff and the licensee did a good job on
this.
MEMBER KRESS: Same here.
DR. BARTON: I have got a question, and in
reviewing the SER, it has to do with the section on
containment. You guys don't have it in front of you,
but 204 and 205, where we talk about the structures
and monitoring systems program that the applicant has
got to manage aging and concrete structures below
ground and water level.
The program will monitor degradation of
water proofing membranes and water stops by evidence
of ground water leakage, accessible to internal
surfaces, et cetera, et cetera.
The bottom line is that the staff reviewed
this information and found that excluding the water
proofing membrane and water stops from the scope of
license renewal is acceptable because degradation of
the water stops will not affect the containment
integrity.
Now, have you guys noticed any leakage at
your containment water stops?
MR. SPICLER: My name is Bruce Spicler and
I am the lead civil engineer for license renewal for
Florida Power and Light.
I guess the key answer would be that we
have done inspections in the independent ten and
access gallery, and in fact during the NRC inspection,
one of the inspectors went with us into the ten and
access gallery.
The areas where we have water stops that
are cast in the concrete, we have not had any leaks.
We have a seal that is between the safety related
containment structure and the non-safety related ten
and access gallery structure which ensures that the
two structures are independent from each other.
We have experienced leaks in that seal,
but that seal is unique to that location. It is not
replicated in safety related structures. But the
question I have is how can you say so now there is a
leak, and there is some seepage of ground water, and
you are seeing it in this membrane.
How can you say that this does not
compromise containment integrity? What happens in an
accident with your pressurized containment? Can you
now drive activity into ground water, and that is my
question.
MR. SPICLER: Well, you are asking if we
can maintain containment integrity, and one of the
things that we explained in our response to the RAIs
was that we are using the ten and access gallery as
the early indicator for signs of degradation to the
concrete below ground water.
DR. BARTON: Right.
MR. SPICLER: It is like a one foot thick
wall, I believe my recollection is, where the
containment, the safety related portion of containment
is many feet.
So our assertion is that if there was to
be degradation, or in other words, we lose the
waterproofing membrane, and then we have intrusion of
ground water through the concrete, and past the water
stops embedded in the concrete, it would show up there
first before it would show up, say, inside
containment.
DR. BARTON: So during an accident there
is no way that you could get accident generated water
-- you see where I am going with this -- accident
generated water back into ground water.
MR. HALE: My name is Steve Hale, Florida
Power and Light. The water stop is to prevent water
from coming in at a construction joint, and internally
we have a liner, which is tested fully as part of our
integrated leak break test and that sort of thing.
And so a water stop itself is not really
related to pressure integrity. It is a circular seal
that is put into a construction joint, where that
construction joint is below ground water level.
And so it is really a construction
feature. Now, what we haw is a similar seal in this
ten and access gallery. So we are using it as a
monitor of the effectiveness of the water stop, and
whether we are seeing any aging in that water stop,
which is very similar to the one that we have for the
containment base path.
DR. BARTON: If you are telling me that
there is no path for radioactive water to get to
ground water through a leak in a seal, that's all I
wanted to know.
MR. HALE: Right. Exactly. The liner is
the pressure package.
DR. BARTON: That is the only question
that I have got, and other than reviewing the SER, I
don't have any other open items. If I could say
something not technical. Am I allowed to say
something not technical before this committee?
CHAIRMAN BONACA: Anything that is proper.
DR. BARTON: I was impressed with the
tour, and I think from what we saw, and in a snapshot
and being familiar with other plants and in looking at
other plants, I think they have got a good safety
culture here, and I think the condition of this plant
in the environment it is in, as compared to other
plants that I have seen outside turbines, et cetera,
and less harsher environments, this plant has got
better material conditions than I have seen in other
stations.
And so I think my assessment is that they
are doing a real good job of maintaining the station.
CHAIRMAN BONACA: I agree with those
comments that were said. And that this is a good
application, and that is my judgment, and a very
extensive review, and I appreciate the review
performed by the staff.
I think it was thorough, and I was
impressed by the inspections that took place over a
period of two years. So we depend on inspections, and
that's why I want to recognize you for this. With
regard to next week's meeting, and I will give you my
thoughts on that, and then go around the table for
additional thoughts.
But certainly we did not have an interim
presentation to the full committee when we had the SER
with open items because there were only four open
items.
MR. AULUCK: We did have the full
committee meeting.
DR. BARTON: Yes, we did.
CHAIRMAN BONACA: We did?
MR. AULUCK: Yes.
CHAIRMAN BONACA: Yes, you are absolutely
right. I think that I still would like to have during
the presentation some points regarding methods used
for scoping and screening. And we are trying to
monitor here from application to application how much
we are depending on generic documents, and I don't
know to what extent it was used.
I know that a lot of previous experience
was used in the application that you put together.
Clearly we need to hear about closure on open items.
One thing that would be interesting to
know for the committee is the bottom line on past
measure components. You know, the active vessel. You
know, 48 effective technical power years and the
margin to that.
And the other thing that I thought would
be important is just a brief discussion of the
Westinghouse topicals, because we will see those again
for the next Westinghouse application.
So although they were not used as a
reference in this application, I think that we may
want to briefly give us a summary, and if nothing
else, that you have completed the review of those.
MR. AULUCK: And we will have the whole
afternoon for a presentation.
CHAIRMAN BONACA: Yes. That's right. And
I will go around the table to see if there are other
issues that we should attach on.
MEMBER KRESS: I agree with what you have.
I would not spend a lot of time on the Westinghouse
because we can get those later.
But when we talk about the open items and
how they were resolved, I would like to see for the
Seismic II over I a little more explanation of the
criteria that were used to decide the impact of the
non-safety and safety, and how they decided what that
impact would be, or whether there was any impact. So
just some criteria or some statements on how they made
their determination.
DR. SIEBER: I have nothing to add.
CHAIRMAN BONACA: This will be a two hour
meeting?
MR. DUDLEY: And the date -- I would like
to correct the date, and that is Thursday, April 11th.
MR. AULUCK: It has been changed?
MR. DURAISWAMY: I believe it is the 11th,
but let's look at the date. We were thinking about
doing it first thing in the morning, 8:30. Is that
okay? It will be on Thursday morning.
DR. BARTON: If Tom's comment had to do
with the description of the Seismic II over I program
here to the full committee; is that what you were
talking about, what we heard this morning from Steve?
MEMBER KRESS: Yes, but I would like to
see specifically how they determined if it had no
impact or if it had an impact, how they were citing
that, the criteria.
CHAIRMAN BONACA: That covers pretty much
the scope, and we will have an hour for the applicant
and an hour for --
MR. DURAISWAMY: You want two hours,
Mario?
CHAIRMAN BONACA: We should take that. I
think we will need two hours. I think you wanted to
talk about station blackout stuff.
CHAIRMAN BONACA: Yes, exactly. We should
talk about the issues of station blackout. And there
are these issues presented to us and should we have
them on the agenda?
MR. DUDLEY: We should probably bring that
forward to the full commission.
MR. AULUCK: Do you want us to discuss
public citizens comments?
CHAIRMAN BONACA: I would like for you to
discuss it, yes. Those are the issues, and regarding
the concrete and the voids in it, and that would be
again interesting to know for the committee what was
done then in looking at other plants. I am sure that
there was something in the stuff there to be
addressed. Any other issues?
MR. AULUCK: Regarding station backup, the
issue was not raised at Turkey Point, and there was no
RAI on it.
CHAIRMAN BONACA: It is an emerging issue,
and I think it is important. I know that I came here
with a question in my mind how do you close this issue
here, because there is a document from the staff with
specific guidance talking about that, and that is not
a prescriptive approach, and the assumption that
outside power is the preferred source. But I am
saying that I think the committee should hear about
that.
MR. GRIMES: We will present the status of
the station blackout issue and understand it, and we
will specifically say that we have not attempted to
apply that position on this plant.
CHAIRMAN BONACA: Exactly.
MR. GRIMES: Because the staff did not
believe that the position was ripe enough. We are
still having an ongoing debate about whether or not
the current licensing basis does nor does not include
off-site equipment, or whether or not the industry's
view will prevail that the station blackout rule stops
when you get AC power.
And it does not go to the restoration
period or the recovery.
CHAIRMAN BONACA: Does that mean that this
is not a closed issue yet?
MR. GRIMES: It is not an open issue on
this application. It is not a closed issue
generically. We sent a letter to NEI and the Union of
Concerned Scientists, and said that we are proposing
to expand the scope of equipment and license renewal
to include the equipment that is used to restore off-
site power based on this interpretation of 50.63.
And that stimulated a dialogue that is
going to end in a decision and we have not made that
decision yet.
CHAIRMAN BONACA: Okay. Good. Thank you
very much. I know that this is a proposed item, yes.
MEMBER KRESS: I guess I would be
interested in hearing a little more about from the
staff about the question of the concrete compaction
and why you feel like it is not a generic issue.
And what you have done in the disposition
is a generic issue. And with respect to the licensing
renewal, it just says it is a generic issue.
CHAIRMAN BONACA: Okay. I think you are
going to have plenty to talk about in NRR. Any other
comments from the members or any comments from them
members of the public?
(No response.)
CHAIRMAN BONACA: If not, then this
meeting is adjourned.
(Whereupon, at 4:30 p.m., the meeting was
concluded.)